Dart-initiated multistage high pressure fracturing system

ABSTRACT

A system and method for fracturing multiple zones in a hydrocarbon well is provided. The system comprises a series of multistage fracturing devices (MFD&#39;s) that are connected along a casing or completion tubing string and have ports that can be opened to allow fracturing of the formation adjacent the MFD. The ports in each MFD are triggered to open by a dart having a specific geometry that is pumped downhole and caught by a catching mechanism that comprises levers or “fingers” in the MFD. Upon catching of the dart, the section downhole of the dart can be sealed off and the ports located uphole of the dart can be opened to allow fracturing operations to occur.

FIELD OF THE INVENTION

The invention generally relates to a system and method for fracturingmultiple zones in an oil and gas well. The invention specificallyrelates to a system and method comprising a series of multistagefracturing devices operatively connected along a tubing string, whereinthe sealing of the tubing string where a multistage fracturing device islocated is triggered by a dart of specific dimensions that is pumpeddown the tubing string and captured by the multistage fracturing device.

BACKGROUND OF THE INVENTION

In the oil and gas industry, during well completion operations, there isoften a need to conduct different operations at various zones within thewell in order to enhance production from the well. That is, within aparticular well, there may be several zones of economic interest thatafter drilling and/or casing, the operator may wish to access the welldirectly and/or open the casing in order to conduct fracturingoperations to promote the migration of hydrocarbons from the formationto the well for production.

In the past, there have been a number of techniques that operators haveutilized in cased wells to isolate one or more zones of interest toenable access to the formation as well as to conduct fracturingoperations. In the simplest situation, a cased well may simply need tobe opened at an appropriate location to enable hydrocarbons to flow intothe well. In this case, the casing of the well (and any associatedcement) may be penetrated at the desired location such that interior ofthe well casing is exposed to the formation and hydrocarbons can migratefrom the formation to the interior of the well.

While this basic technique has been utilized in the past, it has beengenerally recognized that the complexity of penetrating steelcasing/cement at a desired zone is more complicated and more likely tobe subject to complications than positioning specialized sections ofcasing adjacent a zone of interest and then opening that section afterthe well has been cased. Generally, if a specialized section of casingis positioned adjacent a zone of interest, various techniques can beutilized to effectively open one or more ports in a section of casingwithout the need to physically cut through the steel casing.

In other situations, particularly if there is a need to fracture one ormore zones of the formation, systems and techniques have been developedto isolate particular sections of the well in order to both enableselective opening of specialized ports in the casing and conductfracturing operations within a single zone.

One such technique is to incorporate packer elements and variousspecialized pieces of equipment into one or more tubing strings, run thetubing string(s) into the well and conduct various hydraulic operationsto effect opening of ports within the tubing strings.

Importantly, while these techniques have been effective, there has beena need for systems and methods that minimize the complexity of suchsystems. That is, any operation involving downhole equipment isexpensive in terms of capital/rental cost and time required to completesuch operations. Thus, to the extent that the complexity of theequipment can be reduced and/or the time/personnel required to conductsuch operations, such systems can provide significant economicadvantages to the operator.

In the past, such techniques of isolating sections of a well haveincluded systems that utilize balls within a tubing string to enablesuccessive areas of a tubing string to be isolated. In these systems, aball is dropped/pumped down the tubing string where it may engage withspecialized seats within the string and thereby seal off a lower sectionof the well from an upper section of the well. In the past, in order toensure that a lower section is sealed before an upper section, a seriesof balls having different diameters are dropped down the tubing startingwith a smallest diameter ball and progressing uphole with progressivelylarger balls. Typically, each ball may vary in diameter by ⅛^(th) of aninch and will engage with a downhole seat sized to engage with aspecific diameter ball only. While effective, this system is practicallylimited by the range in diameters in balls. That is, to enable 16 zonesof interest to be isolated, the smallest ball would be 2 inches smallerin diameter compared to the largest ball. As a result, there arepractical limitations in the number of zones that can be incorporatedinto a tubing string which thus limits the number of zones that can befracturing. As a modern well may wish to initiate up to approximately 40or more fracturing operations, typical ball drop and capture systemscannot be incorporated into such wells.

Thus, there has been a need for a system that is not limited by the sizeof the balls being dropped and that can enable a significantly largernumber of fracturing windows to be incorporated within a tubing string.

SUMMARY OF THE INVENTION

In accordance with the invention, there is provided a device forconnection to a casing or completion tubing in a wellbore to enablefluid access between an inner cavity of the device and a zone ofinterest in a hydrocarbon formation adjacent the device, the innercavity being continuous with an internal bore in the casing orcompletion tubing, the device comprising an outer sleeve for operativeconnection to the casing or completion tubing, the outer sleeve havingat least one port to enable fluid access between the inner cavity andthe zone of interest; a catchment system operatively retained within theouter sleeve for catching a projectile moving through the inner cavity;a sealing system operatively retained within the outer sleeve forsealing a downhole section of the device from an uphole section of thedevice when the projectile is caught; wherein the at least one port canbe opened through hydraulic activation when the sealing system issealed; and wherein an outer profile of the projectile determineswhether the projectile will be caught.

In one embodiment of the invention, the projectile includes at least oneshoulder on the outer profile, and the location and dimensions of the atleast one shoulder determines whether the projectile will be caught bythe catchment system. Furthermore, a first projectile having an outerdiameter and an outer profile will be caught, while a second projectilehaving the same outer diameter as the first projectile and a differentouter profile will pass through the catchment system.

In another embodiment, the catchment system comprises a plurality oflevers pivotably connected around the circumference of the inner cavity,wherein the levers operatively engage with a projectile having a certainouter profile. The catchment system may further comprise a biasing meansin operative connection with the levers for biasing the levers in afirst position.

In yet another embodiment, the sealing system comprises a piston and asealing member positioned uphole and adjacent to a caught projectile,the sealing member deformable against the caught projectile by hydraulicactuation of the piston to seal the downhole section from the upholesection of the device.

In a further embodiment, the catchment system is in a first shearingengagement with the outer housing, and wherein catchment of a projectileenables the first shearing engagement to disengage and the catchmentsystem to move downhole with respect to the outer housing to enable thesealing system to seal. Further, the catchment system may be in a secondshearing engagement with the outer housing, and wherein sealing of thesealing system enables the second shearing engagement to disengage andthe catchment system to move further downhole with respect to the outerhousing to open the at least one port.

In one embodiment, the caught projectile can be released from thecatchment system to re-open the inner cavity. The caught projectile maybe dissolvable.

In another aspect of the invention, there is provided a system for usein a wellbore comprising a plurality of the above-described devices,each device connected to the casing or completion tubing at a differentlocation to selectively enable access to a zone of interest at eachlocation by sending a projectile downhole from a well surface, theprojectile having an outer profile configured to be caught by thecatchment system at the desired location.

In a further aspect of the invention, there is provided a method forselectively enabling fluid access to a plurality of zones in a wellborecomprising the steps of: (a) running an assembly having a plurality ofactuatable devices into a wellbore having a plurality of zones, eachdevice actuatable between a closed state and an open state, wherein inthe open state fluid access between an internal bore of the assembly anda zone adjacent each device is enabled; (b) selectively actuating adevice at the desired zone by dropping a projectile having an outerprofile with dimensions to be caught by the device at the desired zone;catching the projectile in the device at the desired zone; applyinghydraulic pressure in the internal bore from a well surface to seal asection downhole of the caught projectile from a section uphole of thecaught projectile; and applying hydraulic pressure to move a member inthe device downhole with respect to the assembly to open at least oneport to provide fluid access between the internal bore and the adjacentzone; (c) performing well operations that require access to the desiredzone; and (d) repeating steps b) and c) to successively actuate otherdevices in the assembly.

In a further embodiment, the outer profile of the projectile includes atleast one shoulder, and the position and dimensions of the shoulderdetermine whether the projectile is caught by a device.

In one embodiment, the projectile is caught by pivotable levers in thedevice.

In another embodiment, the plurality of devices are successivelyactuated in a downhole to uphole direction.

In a further embodiment, the well operations include fracturingoperations.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is described with reference to the accompanying figures inwhich:

FIG. 1 is a schematic diagram of a deployed casing or completion tubingstring incorporating several multi-stage fracturing devices inaccordance with the invention together with corresponding packerelements.

FIG. 2 is a perspective view of a multi-stage fracturing device (MFD) inaccordance with the invention. The outer housing is removed for purposesof illustration.

FIGS. 3A, 3B and 3C are perspective views of a catcher mechanism of theMFD sequentially illustrating a dart being captured in accordance withthe invention.

FIG. 4 is a partial perspective view of the MFD illustrating an outerhousing having a plurality of ports in a closed position, wherein theports can be opened to allow for fracturing operations to occur.

FIG. 5 is a perspective view of a support mechanism of the MFD.

FIGS. 6A, 6B and 6C are a series of a cross-sectional side view of theMFD illustrating the normal position of the MFD wherein a dart isentering the uphole end of the MFD but has not yet been captured.

FIGS. 7A to 7F are a sequence of partial cross-sectional side views ofthe MFD illustrating a dart being captured by the catcher mechanism.

FIGS. 8A to 8F are a sequence of partial cross-sectional side views ofthe MFD illustrating a dart passing through the catcher mechanismwithout being captured due to the geometry of the dart.

FIGS. 9A, 9B and 9C are a series of a cross-sectional side view of theMFD illustrating the first stage of operation wherein a dart is capturedby the catcher mechanism.

FIGS. 10A, 10B and 10C are a series of a cross-sectional side view ofthe MFD illustrating the second stage of operation wherein the supportmechanism has been set to brace the captured dart.

FIGS. 11A, 11B and 11C are a series of a cross-sectional side view ofthe MFD illustrating the third stage of operation wherein the sealingmechanism has been set to seal off a downhole section from an upholesection of the tubing string.

FIGS. 12A, 12B and 12C are a series of a cross-sectional side view ofthe MFD illustrating the fourth stage of operation wherein the portshave been opened to ready the MFD for the commencement of fracturingoperations.

FIG. 13 is a side view of a dart in accordance with one embodiment ofthe invention.

FIG. 14A is a partial cross-sectional side view of the MFD illustratingthe sealing mechanism in the first (unsealed) stage of operation as inFIGS. 9A-9C.

FIG. 14B is a partial cross-sectional side view of the MFD illustratingthe sealing mechanism in the second stage of operation as in FIGS.10A-10C, wherein there is a pressure differential to allow the piston toset the sealing mechanism.

FIG. 14C is a partial cross-sectional side view of the MFD illustratingthe sealing mechanism in the third (sealed) stage of operation as inFIGS. 11A-11C.

DETAILED DESCRIPTION OF THE INVENTION

With reference to the figures, a multistage fracturing device (MFD) 10and methods of operating the MFD are described.

For the purposes of description herein, the MFD 10 may be configured toa casing or completion tubing string 4 together with appropriate packerelements 10 a to enable the isolation of particular zones 8 a within aformation as shown in FIG. 1. The combination of MFDs 10 and packerelements 10 a on a casing or completion tubing 4 enable fracturingoperations to be conducted within a formation zone 8 a within a well 8.Alternatively, the system may be utilized without packer elements insituations for example where the completion tubing is cemented in place.While the following description assumes the use of packer elements 10 a,this is not intended to be limiting.

Operational Overview

With reference to FIG. 1, a number of MFDs 10 are connected to a casingor completion tubing 4 between packer elements 10 a at positions thatcorrespond to zones of interest (formations) 8 a within the well.Generally, after placement of the casing or completion tubing 4 withinthe well 8, the assembled system can be pressurized at the surface 6through wellhead equipment 6 a to cause the packer elements 10 a to sealagainst the well 8. Thereafter, a dart 18 is released at the surface 6within the casing or completion tubing and falls and/or is pumpedthrough the casing or completion tubing to engage with a specific MFD,preferably the MFD located nearest the downhole end 4 a of the tubing.The dart has a specific external geometry and diameter that enables thedart to be captured by a specific MFD 10 and to pass through other MFD'swithout being caught.

When the dart 18 is captured, shown in zone 8 a of FIG. 1, the dartcauses the interior of the casing or completion tubing to be sealed fromthe lower regions of the casing or completion tubing such thatadditional hydraulic events can be initiated to open a plurality ofports within the MFD that the dart is captured in. That is, when thedart has been captured and a port in the MFD 10 is opened, a fracturingoperation can be completed within a zone of interest 8 a adjacent thatMFD.

After a zone 8 a has been fractured, further darts are successivelyintroduced into the casing or completion tubing to enable successiveMFDs to be opened and fracturing operations to be completed within otherzones. As a result, each of the zones of interest within the well 8 canbe sequentially fractured moving from the downhole end of the tubingupwards.

Importantly, the darts are designed such that over a period of time,typically a few days, the darts will at least partially dissolve suchthat their diameter is eroded and they will fall to the bottom of thewell. Thus, after all fracturing operations have been completed, all thezones of the well are then opened to the interior of the casing orcompletion tubing to enable production of the well through the casing orcompletion tubing.

It should be noted that the lowermost zone of the completion string doesnot require an MFD 10 and that a simple hydraulic valve that opens onpressure would normally be utilized at the lowermost zone (not shown) toinitially establish circulation and to enable fracturing of thelowermost zone.

Structural Overview

Referring to FIG. 2, the MFD 10 generally comprises an upper housing 14,a sealing mechanism 20, a catcher mechanism 30, a support mechanism 40,a lower housing 16, and a continuous inner cavity 50 extending from anuphole end 10 b to a downhole end 10 c of the MFD that is in fluidcommunication with the completion tubing and through which a dart 18(not shown in FIG. 2) moves to trigger the setting and sealing mechanicsof the MFD. The components of the MFD illustrated in FIG. 2 are allcontained within an outer housing, which has been removed forillustrative purposes. The operation and components of the system aredescribed in greater detail below.

Dart 18

The dart 18 is shown entering the uphole end 10 b of the MFD innercavity 50 in FIG. 6A. In one embodiment, shown in FIG. 13, the dart iscylindrical-shaped and has a leading end 18 a with a beveled edge 18 fand a circumferential leading shoulder 18 b; a trailing end 18 c with acircumferential trailing shoulder 18 d; and an outer surface 18 e. Thewidest part of the dart's diameter is located between the leadingshoulder 18 b and the leading end 18 a. The geometrical configurationand diameter of the dart determines whether the catcher mechanismcatches the dart or allows the dart to pass through and continuedownhole to subsequent MFD's, one of which may have a catcher mechanismsized to catch the dart. Other geometrical configurations of the dartthan that which is illustrated could also be used as will be explainedbelow.

Preferably, the dart has an approximate diameter in the range of 3.25 to3.75 inches and an approximate length of 4 to 6 inches.

After completion of the fracturing operations, the darts are releasedfrom the catcher mechanism and flowed back to the surface to re-open theinner cavity 50. Preferably, the dart is made of dissolvable, ordegradable composite material, such that after a period of time,typically a few days, the dart will at least partially dissolve suchthat its diameter is reduced and it will fall to the bottom of the well,thereby re-opening the inner cavity. Alternative means for releasing thedart could also be used including systems having dissolvable componentswithin the catcher mechanism or electronic release systems.

Housing 12, 14, 16

The cross-sectional view of the MFD 10 in FIGS. 6A to 6C illustrates thehousing elements which comprise the outer housing 12, the upper housing14 and the lower housing 16.

The outer housing 12 contains the components of the MFD and generallycomprises an uphole end 12 a, a downhole end 12 b and a plurality ofports 12 d, shown in FIG. 4, that when open, allow fluid access from theinner cavity 40 to the formation for completing fracturing operations,and when closed, seal the inner cavity from the formation. The at leastone piston shear pin 24 c (FIGS. 2 and 4) removably connects the outerhousing 12 to a piston sleeve of the sealing mechanism 20.

The upper housing 14 is partially retained within and in sealingconnection with the outer housing uphole end 12 a. An uphole end of theupper housing is in sealing connection with the casing or completiontubing 4.

The lower housing 16 is partially retained within and in sealingconnection with the outer housing downhole end 12 b, and comprises anouter shoulder 16 c for abutment with the outer housing downhole end,and an inner shoulder 16 b for abutment with a support sleeve 44 of thesupport mechanism 40 when the system is in the final downhole position(FIGS. 12 to 12C). The lower housing 16 includes a plurality of shearpin holes 16 a through which the downhole shear pins 52 are inserted toconnect the lower housing to the support sleeve 44. A downhole end ofthe lower housing is in sealing connection with the casing or completiontubing 4.

Various sealing elements, such as o-rings, are employed between thehousing elements in circumferential grooves for sealing purposes.

Catcher Mechanism 30

The catcher mechanism 30 functions to “catch” or trap the dart 18 as itmoves downhole through the MFD inner cavity 50 if the dart isdimensioned to be caught. Referring to FIG. 2, the catcher mechanism 30generally comprises a catcher sleeve 32, a catcher member 34 and acatcher spring 36.

Catcher Member 34

Referring to FIGS. 3A and 7A, the catcher member 34 comprises aplurality of pivotable catcher fingers 34 a spaced apart around thecircumference of the catcher member, each pivotable catcher finger 34 ahaving an uphole end 34 b, a downhole end 34 d and an inner surface 34g, and being pivotable about a dowel pin 34 h that is connected to thecatcher sleeve 32. The inner surface 34 g has an upper shoulder 34 c anda lower shoulder 34 e which are used to catch the dart 18. The catcherfingers 34 a are radially pivotable about a tangential axis of thecatcher member, as shown in FIG. 3B, which allows the catcher member toeither catch a dart 18 or allow the dart to pass through the catchermember. The catcher fingers 34 a also each have an outer tapered surface34 f at the downhole end 34 d that engages the support mechanism 40, asexplained in greater detail below.

Catcher Sleeve 32

Referring to FIG. 3A, the catcher sleeve 32 is connected to the catchermember 34 and generally comprises an uphole end 32 c and a downhole end32 b, the downhole end having a plurality of rigid catcher sleevefingers 32 a spaced apart around the circumference of the catcher sleeve32, interspersed between the pivotable catcher fingers 34 a. At thedownhole end 32 b of each catcher sleeve finger 32 a there is an innertapered surface 32 d for engagement with the support mechanism 40. Thecatcher sleeve uphole end 32 c is attached, preferably by a threadedconnection, to the piston sleeve 24 that forms part of the seal settingmechanism.

Catcher Spring 36

The catcher spring 36 encircles a section of the catcher member 34 andthe catcher sleeve 32 for biasing the pivotable catcher fingers 34 a ina neutral position, wherein the catcher fingers are generally parallelwith the axis of the inner cavity 50 (shown in FIGS. 3A and 6B).Preferably, the catcher spring 36 is a collet spring that forms a collararound the catcher member 34 and catcher sleeve 32. In one embodiment,the catcher spring 36 has a plurality of fixed arms 36 a interspersedwith a plurality of biasing arms 36 b. The fixed arms are attached tothe rigid catcher sleeve finger 32 a by fastening means, such as screwsor pins 36 c operatively retained within apertures 32 e in the catchersleeve. The biasing arms 36 b are biased against the pivotable catcherfingers 34 a.

Support Mechanism 40

The support mechanism 40, shown in FIG. 5, comprises a support member42, a support sleeve 44, and a support spring 46. The support member andthe support sleeve work in conjunction with the catching mechanism 30 tosupport the dart 18 after it has caught.

Support Member 42

Referring to FIGS. 5 and 10B, the support member 42 is similar to thecatcher member 34 in that it comprises a plurality of radially pivotablesupport fingers 42 a spaced apart around the circumference of thesupport member 42 that pivot about a tangential axis of the supportmember. Each pivotable support finger 42 a has an uphole end 42 b withan upper shoulder 42 c on the inner surface, and an outer taperedsurface 42 d. Each pivotable support finger 42 a is lined up end to endwith a corresponding rigid catcher sleeve finger 32 a along thelongitudinal axis of the MFD, as shown in FIG. 2. The pivoting of thesupport fingers 42 a allows a dart 18 to pass through the support member42 if it was not caught by the catcher mechanism 30.

Support Sleeve 44

Referring to FIG. 5, the support sleeve 44 is in operative connectionwith the support member 42, and has a similar structure to the catchermember 34. The support sleeve 44 generally comprises an uphole end 44 fand a downhole end 44 b, the uphole end 44 f having a plurality of rigidsupport sleeve fingers 44 a spaced apart around the circumference of thesupport sleeve 44 each having an inner tapered surface 44 e andinterspersed between the pivotable support fingers 42 a. Each rigidsupport sleeve finger 44 a is lined up end to end along the longitudinalaxis of the MFD 10 with a corresponding pivotable catcher finger 34 a,as shown in FIG. 2.

The support sleeve downhole end 44 b is shearingly engaged with thelower housing 16 via at least one shear pin 52. Preferably, the supportsleeve downhole end 44 a has a circumferential groove 44 c that receivesthe at least one shear pin 52. Upon breaking of the at least one shearpin 52 via fluid pressure, the support sleeve 44, along with the entiresupport mechanism 40, catcher mechanism 30 and sealing mechanism 20,moves downhole with respect to the lower housing 16, outer housing 12and upper housing 14 into a final downhole position, shown in FIGS. 12Ato 12C.

Support Spring 46

The support spring 46 is similar in structure and function to thecatcher spring 36. The support spring 46 encircles a section of thesupport member 42 and the support sleeve 44, as shown in FIG. 5, forbiasing the pivotable support sleeve fingers 44 a in a neutral position,wherein the pivotable support sleeve fingers are generally parallel withthe axis of the inner cavity 50 (shown in FIGS. 5 and 6B). Preferably,the support spring 46 is a collet spring that forms a collar around thesupport member 42 and support sleeve 44 and has a plurality of fixedarms 46 a interspersed circumferentially with a plurality of biasingarms 46 b. The fixed arms 46 b are attached to the rigid support sleevefingers 44 a by fastening means, such as screws or pins 46 c operativelyretained within apertures 44 d (shown in FIG. 6B) in the support sleeve44. The biasing arms 46 b are biased against the pivotable supportfingers 42 a.

Sealing Mechanism 20

Referring to FIGS. 6A and 6B, the sealing mechanism 20 generallycomprises a piston 22, a piston sleeve 24 and a compressible seal 26.The sealing mechanism 20 enables the sealing of a downhole section 54 ofthe MFD and casing or completion tubing located downhole from the seal26, from an uphole section 56 located uphole of the seal when a dart 18is captured to enable fracturing operations to occur. FIGS. 14A, 14B and14C are close up views of most of the sealing mechanism 20 (they do notshow the entire piston sleeve 24) from FIGS. 9A-9C, 10A-10C, and11A-11C, respectively, illustrating the sequence of setting the sealingmechanism.

Piston Sleeve 24

The piston sleeve 24 is operatively retained within and connected to theouter housing by the at least one piston shear pin 24 c (FIGS. 2 and 4)located in at least one shear pin groove 24 f (FIG. 14A). The pistonsleeve generally comprises an uphole end 24 a and a downhole end 24 b,the downhole end connected to the catcher sleeve 32 of the catchermechanism 30, and the uphole end 24 a adjacent but not connected to theupper housing 14. At least one vent hole 24 d (FIG. 14A) exists betweenthe piston sleeve and the catcher sleeve 32 for providing pressure tothe piston 22, as discussed in more detail below.

Within the outer housing 12, the piston sleeve 24 is movable from afirst uphole position, shown in FIGS. 9A-9C and FIG. 14A, to a secondintermediate position, shown in FIGS. 10A-100 and FIG. 14B, to the finaldownhole position, shown in FIGS. 11A-110 and FIG. 14C. In the firstuphole position and the second intermediate position, the outer housingmain ports 12 are covered by the piston sleeve 24 and therefore closed.In the final downhole position, the piston sleeve 24 has moved downholepast the outer housing main ports 12, opening the ports 12 such thatthey are in fluid engagement with the inner cavity 50 in order forfracturing operations to occur.

Shearing of the piston shear pin 24 c due to an increase in fluidpressure in the completion tubing causes the movement of the pistonsleeve 24, along with the rest of the sealing mechanism 20 and thecatcher mechanism 30, from the first uphole position to the secondintermediate position. Shearing of a second downhole shear pin 52, asdiscussed in further detail below, due to a further increase in fluidpressure, causes the movement from the second intermediate position tothe final downhole position.

Piston 22 and Compressible Seal 26

Referring to FIG. 14A, the piston 22 comprises an uphole end 22 a and adownhole end 22 b and is operatively retained and moveable within asection of the piston sleeve 24 and the catcher sleeve 32. At least onechamber 72 at atmospheric pressure or a pressure lower than the annuluspressure is provided between the piston 22 and catcher sleeve 32.

The compressible seal 26 is preferably a ring-shaped seal, having anuphole end 26 a bordering the piston downhole end 22 b, and a downholeend 26 b bordering the catcher fingers uphole end 34 b.

When the piston 22 moves downhole, it causes the compressible seal 26 todeform and compress against the catcher fingers 34 and a captured dart18, as shown in FIGS. 11B and 14C, thereby providing a high pressureseal between the downhole section 54 of the MFD downhole of the seal andthe uphole section 56 uphole of the seal.

To stroke the piston 22 and move it downhole to compress the seal, apressure differential is developed as shown in FIGS. 14A to 14C. Priorto the at least one shear pin 24 c (contained within shear pin groove 24f) shearing (FIGS. 14A and 9A-9C), the piston is pressure balancedbecause the vent hole 24 d, which provides pressure to the piston, issealed from the annulus pressure by a seal in a seal groove 24 e locatedbetween the piston sleeve 24 and the outer housing 12. When the at leastone shear pin shears and the sealing mechanism 20 and catcher mechanism30 move from the first uphole position to the second intermediateposition, described above, and shown in FIGS. 14B and 10A-10C, the sealand seal groove 24 e no longer seal, exposing the vent hole 24 d to thedownhole annulus pressure. The chamber 72, which is at atmosphericpressure or a lower pressure than the downhole annulus pressure, remainssealed, which provides the pressure differential needed to stroke thepiston 22 and cause the piston to move downhole and compress the seal,as shown in FIGS. 14C and 11A-11C.

In one embodiment, the seal is made of rubber, such as hydrogenatednitrile butadiene rubber (HNBR), fluoroelastomer rubber (FKM) (e.g.Viton™), or a combination of synthetic rubbers and composite material.

The compressible seal 26 is one example of a compressible element thatcan be compressed by the piston 22. Other types of compressible elementscould be used.

Inner Cavity 50

The inner cavity 50 is continuous through the MFD from the uphole end 10b to the downhole end 10 c when no dart 18 is caught by the catchermechanism. When no dart has been caught, the inner cavity is comprisedof the inner surfaces of the upper housing 14, piston sleeve 24, piston22, seal 26, catcher sleeve 32, catcher member 34, support sleeve 44,support member 42 and lower housing 16. Various sealing elements, suchas o-rings, are located between the components of the MFD to ensure theinner cavity is tightly sealed.

When a dart 18 has been caught by the catcher mechanism 30, the dartcreates a blockage in the inner cavity 50 that enables the ports 12 d ofthe MFD to open using fluid pressure within the tubing string.Importantly, if a dart has not been captured within the catchermechanism 30, maintaining or increasing the pressure within the tubingstring and the inner cavity 50 does not enable the opening of the ports12 d.

Sequence of Operation

In operation, after one or more MFD's are situated within a casing orcompletion tubing in a well, the following general steps are taken toprepare for fracturing operations in a zone of interest 8 a adjacent anMFD: 1) catchment of the dart; 2) setting of the dart support mechanism;3) setting of the sealing mechanism; and 4) opening of the ports.

Stage 1: Catchment of the Dart

A dart 18 is inserted into the well casing or completion tubing at thesurface 6 and free falls or is pumped downhole into the inner cavity 50of the MFD 10. FIGS. 6A to 6C illustrate the dart 18 entering the innercavity 50. The sequential process of the catcher mechanism 30 catchingthe dart is illustrated in a perspective view in FIGS. 3A to 3C and in across-sectional view in FIGS. 7A to 7F.

In the first step (FIGS. 3A and 7A), no dart is present in the catchermechanism 30 and the pivotable catcher fingers 34 a are biased to theneutral position by the catcher spring 36. Next, referring to FIG. 7B,the dart 18 moves downhole such that the dart leading end 18 a contactsthe pivotable catcher finger uphole ends 34 b, causing the spring loadedcatcher fingers to pivot and allow the dart to continue moving downhole(FIGS. 7C to 7E). That is, as the dart leading end 18 a moves past thecatcher member upper shoulders 34 c (FIGS. 3B and 7C), the uphole end 34b of each pivotable catcher finger 34 a is pivoted radially outwardsagainst the catcher spring 36, causing each catcher finger downhole end34 d to pivot radially inwards. The dart continues to move downhole,with the dart outer surface 18 e maintaining contact with the catcherfinger inner surfaces 34 g (FIG. 7D). During this movement, the biasingforce from the catcher spring 36 causes the pivotable catcher fingers 34a to gradually pivot back towards the neutral position (i.e. the catcherfinger downhole ends 34 d pivots outward and the uphole ends 34 b pivotsinward) as the dart 18 progresses downhole (FIG. 7E).

In the final catchment step (FIGS. 3C and 7F), the dart leading end 18 acontacts the catcher finger lower shoulders 34 e and attempts to pushthe fingers outwards and upwards so the dart can pass through. Howeverthe design of the system does not allow the catcher fingers to pivot outof the way, since the catcher finger uphole ends 34 b are in contactwith the dart lower shoulders 34 e, thereby preventing the catcherfingers from pivoting out of the way and effectively trapping the dart.That is, the dart leading end 18 a and trailing end 18 c are trapped,respectively, by the catcher finger lower shoulders 34 e and uppershoulders 34 c. In this position, the dart has been “caught” by thecatcher member 34 and provides a significant restriction in the cavity50 of the MFD.

The outer geometry of the dart, for example the position of the darttrailing shoulder 18 d, the length of the dart and/or the diameter ofthe dart, determine whether the dart is caught by the catcher mechanism30. FIGS. 8A through 8F illustrate a sequence wherein the dart 18 is notcaught by the catcher member 34 but instead passes through the catchermember. In the illustrated example, the dart trailing shoulder 18 d ispositioned further towards the dart leading end 18 a than in thepreviously referred to sequence illustrated in FIGS. 7A through 7F. Inthis case, when the dart leading shoulder 18 b contacts the catcherfinger lower shoulders 34 e and forces them outwards (FIGS. 8A and 8B),the catcher finger upper shoulders 34 c contact the dart trailing end 18c at a location downhole from the dart trailing shoulder 18 d (FIG. 8D),instead of uphole of the dart trailing shoulder as is the case when thedart is caught by the catcher fingers in the previous example (FIG. 7F).This allows the catcher finger downhole ends 34 d to be pivoted furtheroutwards (FIG. 8E), allowing the dart leading shoulder 18 b to pass bythe catcher finger lower shoulders 34 e (FIG. 8F), thus allowing thedart to pass completely through the catcher member 34.

After the dart has passed through the catcher fingers 34 a, the dartpasses through the support mechanism 40 and continues downhole.Similarly, if a dart 18 has a smaller diameter than a dart that is sizedto be caught by the catcher member 34, the dart would pass through thecatcher fingers without being caught. Alternatively, all or some of thedarts may have the same geometry and diameter, however the length,diameter, and/or inner surface profile of some or all of the catcherfingers is varied in subsequent catcher MFD's.

In the preferred embodiment, approximately 10 stages can be fracturedusing the same diameter of dart but by varying the profile of the dart.For example, if the largest diameter of dart used is 3.75″, and thediameter drops by ⅛″ every 10 stages, then 40 stages could be fracturedbefore the dart size drops below 3.375″. I.e. Stages 1 to 10 use a 3.75″diameter dart; stages 11 to 20 use a 3.625″ diameter dart; stages 21 to30 use a 3.5″ diameter dart; and stages 31 to 40 use a 3.375″ diameterdart.

Stage 2) Setting of the Dart Support Mechanism

After a dart 18 has been caught by the catcher mechanism 30, there is asignificant restriction within the cavity 50 which creates enoughpressure build-up to cause the piston shear pin(s) 24 c to break. Thiscauses the sealing mechanism 20 (i.e. the piston 22, piston sleeve 24and seal 26) and the catcher mechanism 30 (i.e. catcher sleeve 32,catcher member 34, and catcher spring 36) move downhole as one unitwithin the outer housing 12 to contact the support mechanism 40. i.e.The sealing mechanism 20 and catcher mechanism 30 move from the firstuphole position (FIGS. 9A to 9C) to the second intermediate position(FIGS. 10A to 100). The catcher mechanism 30 and sealing mechanism 20are prevented from moving beyond the second intermediate position by theabutment of the downhole end of the catcher mechanism (i.e. the catcherfinger donwhole ends 34 d and catcher sleeve fingers downhole ends 32 b)with the uphole end of the support mechanism 40 (i.e. the support fingeruphole ends 42 b and support sleeve fingers uphole ends 44 f).

In the second intermediate position, there is an interlacing ofalternating fingers such that the pivotable fingers are supported by therigid fingers, thereby setting the dart support system. That is, theouter tapered surface 34 f of each pivotable catcher finger 34 a abutsthe inner tapered surface 44 e of the corresponding rigid support sleevefinger 44 a, thereby causing the rigid support sleeve finger to beardown on the pivotable catcher finger, supporting the pivotable catcherfinger and locking it in place. Similarly, the outer tapered surface 42d of each pivotable support finger 42 a abuts the inner tapered surface32 d of the corresponding catcher sleeve finger, thereby causing therigid catcher sleeve finger 32 a to bear down on the pivotable supportfinger 42 a, supporting the pivotable support finger and locking it inplace.

Setting the dart support system has two purposes: to provide increasedreinforcement to the dart 18 to prevent the dart from pushing throughthe catcher fingers when increased fluid pressures are applied to thesystem in further stages of operation, and to open a path for pressureto create a pressure differential between the uphole end of the piston22 and the atmospheric chamber 70 in the piston, thereby allowing forsetting of the sealing mechanism. The creation of the pressuredifferential was described in more detail above with respect to FIGS.14A-14C

Stage 3) Setting of the Sealing Mechanism

When the dart support system has been set and a pressure differentialcreated, the piston 22 is stroked, moving downhole with respect to theother components of the system, compressing the seal 26 against theuphole end of the pivotable catcher fingers 34 a, catcher sleeve fingers32 a and dart 18 (FIGS. 11A to 11C), thereby sealing the downholesection 54 of the seal from the uphole section 56 of the seal.

Stage 4) Opening of the Ports

In the fourth stage of operation, the fluid pressure is furtherincreased to open the ports 12 d in the outer housing. In this stage, anincrease in fluid pressure in the system causes the shear pins 52connecting the support sleeve 44 to the lower housing 16 to break, thusreleasing the sealing mechanism 20, catcher mechanism 30 and supportmechanism 40 from the housing which then moves downhole as one unit fromthe second intermediate position to the final downhole position shown inFIGS. 12A to 12C. The abutment of the downhole end 44 b of the supportsleeve with the lower housing inner shoulder 16 b acts as a stop toprevent the sealing mechanism, catcher mechanism and support mechanismfrom moving beyond the final downhole position. In this position, thepiston sleeve uphole end 24 a has moved downhole past the ports 12 d,thereby opening the ports and allowing fluid and pressure communicationbetween the inner cavity 50 and the adjacent formation 8 a through theports.

Fracturing Operations

After the fourth stage of operation wherein the ports have been opened,fracturing operations can commence in the zone of interest in theformation 8 a adjacent the ports 12 a. Upon completion of the fracturingoperations in a particular zone, further darts can be successivelyintroduced into the completion tubing to enable successive MFDs to beopened and fracturing operations to be completed within other zones.

Pressurization

The pressure in the completion string will be varied throughout theoperation of the system to trigger the stages to occur. That is, variousstages of the operation may have a threshold pressure that will enableeach stage to be sequentially completed. For example, the pressureinitially starts at typical fracturing circulation pressures for thetype of formation being fractured, which is generally in the range of2000 and 8000 psi. Once a dart has been caught by the catcher mechanism30, the pressure may increase another 500 to 1500 psi over thecirculation pressure to shear the piston shear pin 24 c and move thesealing mechanism 20 and catcher mechanism 30 downhole to set the dartsupport mechanism. The pressure may then increase another 500 to 1500psi to stroke the piston 22 and set the seal 26, after which the seconddownhole shear pin 52 shears in order to open the ports 12 d to allowfracturing operations to occur.

Although the present invention has been described and illustrated withrespect to preferred embodiments and preferred uses thereof, it is notto be so limited since modifications and changes can be made thereinwhich are within the full, intended scope of the invention as understoodby those skilled in the art.

1. A device for connection to a casing or completion tubing in awellbore to enable fluid access between an inner cavity of the deviceand a zone of interest in a hydrocarbon formation adjacent the device,the inner cavity being continuous with an internal bore in the casing orcompletion tubing, the device comprising: an outer sleeve for operativeconnection to the casing or completion tubing, the outer sleeve havingat least one port to enable fluid access between the inner cavity andthe zone of interest; a catchment system operatively retained within theouter sleeve for catching a projectile moving through the inner cavity;a sealing system operatively retained within the outer sleeve forsealing a downhole section of the device from an uphole section of thedevice when the projectile is caught; wherein the at least one port canbe opened through hydraulic activation when the sealing system issealed; and wherein an outer profile of the projectile determineswhether the projectile will be caught.
 2. The device of claim 1 whereinthe projectile includes at least one shoulder on the outer profile, andthe location and dimensions of the at least one shoulder determineswhether the projectile will be caught by the catchment system.
 3. Thedevice of claim 1 wherein a first projectile having an outer diameterand an outer profile will be caught, while a second projectile havingthe same outer diameter as the first projectile and a different outerprofile will pass through the catchment system.
 4. The device of claim 1wherein the catchment system comprises a plurality of levers pivotablyconnected around the circumference of the inner cavity, wherein thelevers operatively engage with a projectile having a certain outerprofile.
 5. The device of claim 4 wherein the catchment system furthercomprises a biasing means in operative connection with the levers forbiasing the levers in a first position.
 6. The device of claim 1 whereinthe sealing system comprises a piston and a sealing member positioneduphole and adjacent to a caught projectile, the sealing memberdeformable against the caught projectile by hydraulic actuation of thepiston to seal the downhole section from the uphole section of thedevice.
 7. The device of claim 1 wherein the catchment system is in afirst shearing engagement with the outer housing, and wherein catchmentof a projectile enables the first shearing engagement to disengage andthe catchment system to move downhole with respect to the outer housingto enable the sealing system to seal.
 8. The device of claim 8 whereinthe catchment system is in a second shearing engagement with the outerhousing, and wherein sealing of the sealing system enables the secondshearing engagement to disengage and the catchment system to movefurther downhole with respect to the outer housing to open the at leastone port.
 9. The device of claim 1 wherein a caught projectile can bereleased from the catchment system to re-open the inner cavity.
 10. Thedevice of claim 9 wherein the caught projectile is dissolvable forreleasing the caught projectile from the catchment system.
 11. A systemfor use in a wellbore comprising: a plurality of devices for connectionto a casing or completion tubing in a wellbore to enable fluid accessbetween an inner cavity of the device and a zone of interest in ahydrocarbon formation, each device of the plurality of devicescomprising: an outer sleeve for operative connection to the casing orcompletion tubing, the outer sleeve having at least one port to enablefluid access between the inner cavity and the zone of interest; acatchment system operatively retained within the outer sleeve forcatching a projectile moving through the inner cavity; a sealing systemoperatively retained within the outer sleeve for sealing a downholesection of each device from an uphole section of each device when theprojectile is caught; wherein the at least one port can be openedthrough hydraulic activation when the sealing system is sealed; andwherein an outer profile of the projectile determines whether theprojectile will be caught, each device connected to the casing orcompletion tubing at a different location to selectively enable accessto a zone of interest at each location by sending a projectile downholefrom a well surface, the projectile having an outer profile configuredto be caught by the catchment system at the desired location.
 12. Amethod for selectively enabling fluid access to a plurality of zones ina wellbore comprising the steps of: a) running an assembly having aplurality of actuatable devices into a wellbore having a plurality ofzones, each device actuatable between a closed state and an open state,wherein in the open state fluid access between an internal bore of theassembly and a zone adjacent each device is enabled; b) selectivelyactuating a device at the desired zone by: dropping a projectile havingan outer profile with dimensions to be caught by the device at thedesired zone; catching the projectile in the device at the desired zone;applying hydraulic pressure in the internal bore from a well surface toseal a section downhole of the caught projectile from a section upholeof the caught projectile; and applying hydraulic pressure to move amember in the device downhole with respect to the assembly to open atleast one port to provide fluid access between the internal bore and theadjacent zone; c) performing well operations that require access to thedesired zone; and d) repeating steps b) and c) to successively actuateother devices in the assembly.
 13. The method of claim 12 wherein theouter profile of the projectile includes at least one shoulder, and theposition and dimensions of the shoulder determine whether the projectileis caught by a device.
 14. The method of claim 12 wherein the projectileis caught by pivotable levers in the device.
 15. The method of claim 12wherein the plurality of devices are successively actuated in a downholeto uphole direction.
 16. The method of claim 12 wherein the welloperations include fracturing operations.